1. Field of the Invention
This invention is directed to a process of recovering petroleum from underground reservoirs.
2. Description of the Prior Art.
Some of the largest known liquid petroleum deposits in the world are the Athabasca tar sands located in northern Alberta. It has been estimated that this area alone contains approximately three hundred billion barrels of oil. Other huge deposits of a similar nature are to be found in various parts of the United States and in Venezuela. Owing to the highly viscous nature of these deposits, their economic production has been extremely difficult. Numerous processes have been employed in efforts to recover such material including processes involving mining and centrifuging the tar and sand in the presence of certain solvents and surface active agents and subjecting the mined tar and sand mixture to treatment with hot water and separating the resulting upper oil layer. These and other methods which have been used, however, all require large labor and capital expenditures.
Underground combustion and steaming as a means of recovering deposits of this type have also been employed. In general, however, the very high differential pressures that must be applied between input and producing wells to recover the oil presents an extremely difficult problem. Frequently, the pressures that must be applied to shallow reservoirs of low permeability, i.e., less than 100 millidarcies, are higher than can either be applied economically or without causing uncontolled fracturing of the formation which would lead to channeling or bypassing, or both.
Conventional underground combustion, i.e., an operation in which the combustion zone is propagated from a point near the face of an injection well toward a producing well, is extremely difficult with heavy viscous hydrocarbons in low permeability reservoirs of the type contemplated herein. Production is difficult in low-permeability reservoirs because the produced oil flows from the hot zone through the unheated zone to the production well. In the combustion zone the viscosity of the oil is at a minimum; however, as the pressure of the system forces the oil toward the producing well, the oil decreases in temperature to that of the unburned portion of the reservoir. Eventually, resistance to flow through the reservoir to the producing well becomes so great that combustion can no longer continue because it is impossible to supply air at a satisfactory rate to the burning zone.
The following U.S. Patents disclose various systems for and methods recovering petroleum from underground formations: U.S. Pat. Nos. 3,327,782, 3,208,514, 3,982,591, 3,982,592, 4,024,912, 4,050,515, 4,077,469, 4,078,613, 4,183,405, 4,199,024, and 4,241,790.
U.S. Pat. Nos. 3,208,514 and 3,327,782 disclose in situ hydrogenation of heavy oil and tar sands based upon achieving hydrogenation temperatures by means of in situ combustion. The use of this technique presents a significant difficulty. In order for hydrogenation of heavy oil or tar sands to take place, it is necessary to contact the oil with heat and hydrogen for a sufficient length of time so that enough of the reaction can take place to upgrade the oil so that it can be produced. In situ combustion is a flow process and by its very nature tends to displace the oil in the formation. When forward combustion is stopped at any point there is a series of zones in the formation, each with its own characteristic temperature. Residual oil displacement areas are shown in FIG. 1 of the present application. Flow starts at the injection well and moves towards a production well. For forward dry combustion these zones are as follows:
Zone 1. (surrounding the wellbore of the injection well) high temperature (300.degree.-800.degree. F.); no oil; no water. PA0 Zone 2. (combustion zone) very high temperature (typically 800.degree.-1000.degree. F. depending upon the permeability of the formation and the original oil and water saturations); steep oil gradient--oil at the boundary with the first zone and 10-20% oil saturation at the other zone boundary; no water as such. PA0 Zone 3. (steam chest) steep temperature gradient from the combustion zone temperature to the temperature for condensing steam at the formation pressure, typically 450.degree.-550.degree. F. for pressures of 400 to 1000 psig; oil saturations of 10-20%; water saturations of up to 80-90%. PA0 Zone 4. (hot water zone) temperatures declining from that at the boundary of zone 3 to formation temperature, oil saturations increasing from 10-20% up to original oil saturations and water saturations decreasing from about 80.degree.-90.degree. at the boundary of zones 3 and 4 to original water saturations.
The oil which is in zone 2 has been distilled and is least susceptible to hydrogenation; it will not be produced because it is in the combustion zone. The same is true of the oil in zone 3 and the combustion zone will soon overtake it. The oil in zone 4 is suitable for hydrogenation but the temperatures there are at most the condensation temperature of steam.
Regardless of when the combustion is stopped and the hydrogen introduced, little or no oil will be at the temperature suitable for hydrogenation; temperatures below 550.degree. F. result in hydrogenation rates which are too slow to be economical. Therefore, dry in situ combustion is not satisfactory for heating the oil in place to hydrogenation temperatures. Similar problems exist with forward wet combustion; it has the additional difficulty that the maximum formation temperatures which it creates are lower than those created by dry combustion.
U.S. Pat. No. 3,327,782 discloses a hydrogenation method for recovery of oil and upgrading the quality of viscous oils based upon heating the formation by means of reverse combustion using air. This has two significant drawbacks:
1. In low permeability reservoirs, it is difficult or, in some cases, impossible to maintain the gas fluxes necessary to achieve burn rates that will heat the formation to the temperatures required for hydrogenation--550.degree. to 900.degree. F.;
2. When using air as the combustion-supporting gas, the resulting partial pressure of the residual nitrogen will be above the original reservoir pressure. In order for hydrogenation to take place at significant rates, the hydrogen partial pressure must be at least 300 psi and preferrably greater than 500 psi. Therefore, it would be difficult, in most cases, to achieve this partial pressure without causing random fracturing of the reservoir overburden and the resulting escape of hydrogen. If hydrogen is used to displace the nitrogen, channeling will occur and only a fraction of the nitrogen will be removed; the result of this will be to have hydrogenation conditions existing in small random pockets of the formation. If the nitrogen is removed by reducing the reservoir pressure, water which had condensed in the formation during the heating step will evaporate and cool the formation to the saturation temperature at the formation pressure. This temperature reduction along with the expansion of the nitrogen and hydrogen will reduce the formation temperature well below that required for economical rates of hydrogenation.
In the process of U.S. Pat. No. 3,327,782, there is hydrogen flow through the formations from the injection well to the production wells. This results in low efficiency for the effective use (uptake) of the hydrogen that has been injected and a major economic cost in terms of lost hydrogen and/or hydrogen recovery from the produced gas.
The process of this patent also requires either a formation having a low permeability less than 100 millidarcies, or, in higher permeability reservoirs, the use of in situ combustion for heat generation. In addition the process might leave uncontrolled quantities of residual oxygen in the formation including oxygenates resulting from incomplete combustion of the oil and free oxygen in the gas saturation. When hydrogen is introduced, the unknown and uncontrolled quantities of oxygen will combine with the hydrogen at the wrong place and time in the process, thereby reducing the hydrogen partial pressure and the effectiveness of the hydrogenation step.
U.S. Pat. No. 3,982,592 discloses a gas generator that may be operated to thermally crack the hydrocarbons (in the formation) into lighter segments for reaction with excess hot hydrogen to form lighter and less viscous end products and to hydrogenate or cause hydrogenolysis of unsaturated hydrocarbons to upgrade their qualities for end use. The term hydrogenation herein is defined as the addition of hydrogen to the oil without cracking and hydrogenolysis is defined as hydrogenation with simultaneous cracking. Cracking is herein defined as the breaking of the carbon bonds with a resulting reduction of the weight of the molecules. The flow of hydrogen and oxygen to the gas generator is controlled to maintain the termperature of the gases flowing through the outlet at a level sufficient to cause hydrogenation of the hydrocarbons in the formations. The cracked gases and liquids move through the formations to a spaced production well for recovery at the surface. Operation of the gas generator provides for a temperature at the outlet of the generator which is sufficient to cause hydrogenation, but the patent does not teach how to effectively contact oil, heat, and hydrogen simultaneously.
U.S. Pat. Nos. 4,183,405 and 4,241,790 also disclose the flow of hydrogen through the formations from an injection well to a production well and also the use of insitu combustion to generate enough heat for hydrogenation to take place and for distillation and cracking purposes.